How Many Gas-Directed Rigs Do We Really Need? - Part II

by: Richard Zeits

In Part I of this note, I reviewed Southwestern Energy's projected production growth in the Marcellus Shale to illustrate the remarkable productivity of "sweet spots" within natural gas resource plays, which has dramatically reduced the requirement for gas-directed rigs. I have suggested that, contrary to common belief, the existing gas-directed rig count is most likely sufficient to maintain the U.S. natural gas production flat in the near term. In this section, I analyze additional production statistics and estimate the decline rate for the Lower 48 production.

Barnet Shale Case Study

In my next example, I turn to the Barnett Shale to estimate the minimum rig count that would be required to maintain the field's production flat. In my analysis, I use the Texas Railroad Commission data for the Barnett production and Baker Hughes data for the field's rig count.

The Barnett Shale presents a valuable reference point due to several attributes that make the Barnett more similar to the overall U.S. onshore natural gas portfolio than any other shale.

  • The Barnett's natural gas production has remained essentially flat for almost five years.
  • The field's volumes include a significant component of lower-decline production from older vintage wells, much larger than in the case of the shales that have experienced recent explosive growth (e.g., Haynesville, Marcellus).
  • The Barnett's production yields a significant NGLs stream, which compensates economically for the relatively low dry gas productivity per rig. The NLGs aspect is particularly important, as the most frequently quoted industry-wide gas directed rig count includes rigs drilling both for dry and liquids rich gas. The dry gas yield per rig from liquids-rich formations is typically markedly lower, often by more than 50%, than from the best "dry gas" areas (while the economics may still be comparable or better).

Among the economically competitive gas resource plays, the Northeast Pennsylvania is at the very high end of dry gas productivity per rig, whereas the Barnett is closer to the low end.

When analyzing the correlation between the Barnett's production and rig count, it is important to factor in the spud-to-peak-production lead times which in the Barnett's case are typically in the six to 10 weeks range. It is also important to take into account significant price-related production curtailments, which impacted the Barnett's production during the first half of 2012 (Chesapeake Energy, a top two producer in the Barnett, announced significant curtailments in January 2012 in response to the declining natural gas prices).

The graph below shows the month-on-month percentage changes in the Barnett's aggregate production versus the two-months-earlier rig count.

(click images to enlarge)

During the period from April 2011 through November 2011, the Barnett's "wet" gas production grew at an average monthly rate of approximately 1%. The corresponding rig count (using a two-month lead time) was 58 rigs, on average. The Barnett's production started to decline in December 2011 as the rig count two months prior crossed below the 50 rig level. I estimate that approximately 48 rigs represented the inflection point from growth to contraction on the production base of approximately 5.7 Bcf/d of "wet" gas, which I assume translated in 4.6-4.8 Bcf/d of dry gas after NGLs extraction. These data suggest that in the Barnett, one rig can offset natural declines on 95-100 MMcf/d of "Barnett-like" base dry gas production.

I should note that in addition to the overall reduction in the rig count, the operating shift towards liquids-rich drilling, and the associated declining dry gas productivity per rig, may have contributed to the declining production trend in the field towards the end of 2011. As an example, Devon Energy, a top two Barnett producer, is currently drilling exclusively in the "wet" window and sees liquids yields of 30%, on average, from its wells (which translates in substantially lower dry gas yields compared to wells in the dry gas window).

Estimating Industry-Wide Base Production Decline

EnCana Fundamentals, whose estimate I will use in this analysis, expects an approximately 20 Bcf/d natural decline in the North American dry gas base production from year end 2011 to year end 2012, as shown in a slide from the company's presentation.

The 20 Bcf/d decline represents approximately 27% of total North American dry gas production volume of 75 Bcf/d as of 2011 year end. In my calculation, I will use the range of [26%-28%] for the Lower 48 base production decline and assume that the decline will remain within that range in the next few years.

According to EnCana, at the end of 2011, the Lower 48 natural gas production included 7.1 Bcf/d of associated gas production, which EnCana forecasts to grow by approximately 0.8 Bcf/d annually in 2012-2013.

The associated gas production is driven by oil-directed rig count. An additional approximately 3 Bcf/d of non-associated natural gas production came from the Gulf of Mexico. The GoM production, which is driven by offshore rig count, has been trending down at a rate of approximately 15-20% annually, which I assume to continue for the next two years. Based on these data, at the end of 2012, the Lower 48 onshore non-associated dry gas production base is likely to be in the 52-54 Bcf/d range. The exclusion of the associated gas production, which is a "young" and fast-declining part of the portfolio, should result in the remaining production having lower-than-average decline rate, which I estimate in the 24.5%-27% range. As a result, gas-directed land rigs will be called upon to offset approximately 12.5-14.5 Bcf/d of annual decline so that total U.S. natural gas production could stay flat.

In Part III, I draw quantitative conclusions regarding the required rig count and discuss possible implications for natural gas and land drilling sectors.

This discussion of natural gas fundamentals bears relevance to natural gas producer and land drilling stocks.

My natural gas producer index includes:

  • Chesapeake Energy (NYSE:CHK)
  • EnCana Corporation (NYSE:ECA)
  • Devon Energy (NYSE:DVN)
  • Southwestern Energy (NYSE:SWN)
  • Ultra Petroleum (NASDAQ:UPL)
  • EXCO Resources (NYSE:XCO)
  • WPX Energy (NYSE:WPX)
  • Cabot Oil & Gas (NYSE:COG)
  • Range Resources (NYSE:RRC)
  • QEP Resources (NYSE:QEP)
  • Quicksilver Resources (NYSE:KWK)
  • Forest Oil (NYSE:FST)
  • Bill Barrett (BBG)

My land drilling index includes:

  • Helmerich & Payne (NYSE:HP)
  • Nabors Industries (NYSE:NBR)
  • Patterson-UTI Energy (NASDAQ:PTEN)
  • Precision Drilling (NYSE:PDS)
  • Unit Corporation (NYSE:UNT)
  • Union Drilling (NASDAQ:UDRL)

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.